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Low-pH fracturing fluid systems face a challenge to maintain rheological stability at elevated temperatures beyond 300°F. The objective is to have a reliable fluid system with high foam quality and viscosity demonstrating required proppant transport and retained permeability at the end of the treatment. To best balance the tradeoff, a solution that has been utilized for many treatments is to viscosify a novel biopolymer-based slurry gel fluid system with CO2. There are associated challenges with this strategy, though, in generating sufficient fracture width to place higher proppant concentrations. In this paper, we summarize a case study where enhancement of foam stability utilizing degradable fiber showed some improvement in proppant placement performance. Degradable polymer fiber with novel polymer rearrangement was utilized to enhance the performance stability and used with the base fluid. Foam half-life was measured by varying fiber concentrations from 0 to 32 lbm/1000 galUS. Static and dynamic proppant transport was also studied by varying fiber concentrations from 0 to 22 lbm/1000 galUS. Proppant utilized for this testing was high-strength ceramic proppant. After the laboratory phase, fracturing treatment was implemented in two wells with CO2-assisted foam fracturing with (Well-B) and without the fibers (Well-A) to analyze the impact on proppant placement. Three different fiber products made of different synthetic polymers were utilized in the initial phase to compare for proppant settling, and the high-temperature (HT) version was selected based on superior proppant suspension at high temperatures. For the next evaluation phase, the addition of HT fibers increased the foam half-life from 100 minutes to 200 minutes for 0 and 32 lbm/1000 galUS loadings, respectively. Similarly, the proppant settling time was increased from 59 minutes to 152 minutes for 0 and 15 lbm/1000 galUS loadings, respectively. Slot tests were conducted in a 3-mm slot to evaluate proppant transport in dynamic conditions and showed no sand banking effect with fibers. Tests were conducted with 0, 8, and 22 lbm/1000 galUS of fibers and show a clear impact of the fiber addition. During the field implementation, the HT fiber addition of 20 lbm/1000 galUS demonstrated 15% lower friction analyzed from treating pressure trends at the end of treatment. Also, no indications of near-wellbore bridging, or entry issues were observed in Well-B, similar to Well-A where CO2 foam was pumped without fibers. The implementation of this approach can be impactful for CO2 foam treatments and can also be easily extended to liquid CO2 or supercritical CO2 fracturing, which provides the worst case environment for friction and proppant transport.
Low-pH fracturing fluid systems face a challenge to maintain rheological stability at elevated temperatures beyond 300°F. The objective is to have a reliable fluid system with high foam quality and viscosity demonstrating required proppant transport and retained permeability at the end of the treatment. To best balance the tradeoff, a solution that has been utilized for many treatments is to viscosify a novel biopolymer-based slurry gel fluid system with CO2. There are associated challenges with this strategy, though, in generating sufficient fracture width to place higher proppant concentrations. In this paper, we summarize a case study where enhancement of foam stability utilizing degradable fiber showed some improvement in proppant placement performance. Degradable polymer fiber with novel polymer rearrangement was utilized to enhance the performance stability and used with the base fluid. Foam half-life was measured by varying fiber concentrations from 0 to 32 lbm/1000 galUS. Static and dynamic proppant transport was also studied by varying fiber concentrations from 0 to 22 lbm/1000 galUS. Proppant utilized for this testing was high-strength ceramic proppant. After the laboratory phase, fracturing treatment was implemented in two wells with CO2-assisted foam fracturing with (Well-B) and without the fibers (Well-A) to analyze the impact on proppant placement. Three different fiber products made of different synthetic polymers were utilized in the initial phase to compare for proppant settling, and the high-temperature (HT) version was selected based on superior proppant suspension at high temperatures. For the next evaluation phase, the addition of HT fibers increased the foam half-life from 100 minutes to 200 minutes for 0 and 32 lbm/1000 galUS loadings, respectively. Similarly, the proppant settling time was increased from 59 minutes to 152 minutes for 0 and 15 lbm/1000 galUS loadings, respectively. Slot tests were conducted in a 3-mm slot to evaluate proppant transport in dynamic conditions and showed no sand banking effect with fibers. Tests were conducted with 0, 8, and 22 lbm/1000 galUS of fibers and show a clear impact of the fiber addition. During the field implementation, the HT fiber addition of 20 lbm/1000 galUS demonstrated 15% lower friction analyzed from treating pressure trends at the end of treatment. Also, no indications of near-wellbore bridging, or entry issues were observed in Well-B, similar to Well-A where CO2 foam was pumped without fibers. The implementation of this approach can be impactful for CO2 foam treatments and can also be easily extended to liquid CO2 or supercritical CO2 fracturing, which provides the worst case environment for friction and proppant transport.
North Kuwait Jurassic Gas (NKJG) fields are challenging HPHT wells with near-critical fluids in reservoir conditions. These wells are deep and sour with 2-8 % H2S and 1-3 % CO2 with average reservoir pressure ranging from 10,000 – 4,000 psi and average reservoir temperature of ~275oF. Best practices in terms of developing these fields by using the best technologies in drilling, completion, and production are essential to maximize the reserve recovery in order to deliver hydrocarbon to the market. Due to anhydrite presence and existing high variation of natural fracture distribution along the wellbore with different lithology and reservoir properties. There is differential pressure depletion happens within the entire reservoir, so these reservoirs have been divided into different flow units based on stratigraphy and pressure differential. These layers have different productivity index based on production logging records and calibrated well production models due to existence of dual-porosity tight matrix with natural fracture system which require proper pinpoint activation protocol by treating these layers separately. During the early development stages of these fields, these wells were completed with tapered type of completion with 3.5″ production tubing, which was used as the optimum flow rate for virgin or slightly depleted reservoirs. Nowadays, Monobore completion has been deployed so that these flow zones can be perforated, activated, stimulated, tested and isolated using plug and perf technique which provide proper stimulation fluids propagation into the target reservoir. In addition, the cluster perforation leads to better effective stimulation fracturing by bypassing formation damage due to drilling, completion & perforation debris from the illustrated case studies. This paper aims to illustrate the successful story of the cluster perforation technique in tight carbonate reservoir layers, and share its impact on pinpoint stimulation and hydraulic fracturing treatment by comparing the production performance of the studied wells with offset wells. As an additional achievement, the cluster perforation leads to cost reduction by reducing the perforation gun length, volumes of pumped treatment/wellbore diverters fluids and accelerating the well hookup to the production facility beside the sustainability of the production during the LTT. Also, that technique is better in terms of reservoir management as it supports depleting the reservoir layers uniformly. The success of this approach was proven by calibrated nodal analysis assessment and sustainability of well production at a stabilized rate, which supports reaching "optimal inflow distribution" along the different flow zones, which become a best practice approach in the newly completed wells aiming to maximize the gas recovery.
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